Polysaccharide coated nanoparticle compositions comprising ions

ABSTRACT

A composition including a coated nanoparticle including a nanoparticle and a cross-linked carbohydrate-based coating and an ion selected from the group consisting of Li+, Na+, K+, Rb+, Cs+, Be2+, Mg2+, Ca2+, Sr2+, Ba2+, and mixtures thereof; methods of making and using the composition; and systems including the composition.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of and claims the benefit of priorityto U.S. patent application Ser. No. 15/205,774, filed Jul. 8, 2016,which claims the benefit of priority to U.S. Provisional ApplicationSer. No. 62/191,881, filed Jul. 13, 2015, the contents of both which arehereby incorporated by reference.

TECHNICAL FIELD

This document relates to methods and compositions used in treatingsubterranean formations for enhancing hydrocarbon fluid recovery.

SUMMARY

Provided in this disclosure is a method of treating subterraneanformations. The method includes placing in a subterranean formation ananoparticle composition. The nanoparticle composition includes (i) acoated nanoparticle including a nanoparticle and a cross-linkedcarbohydrate-based coating and (ii) an ion selected from the groupconsisting of Li⁺, Na⁺, K⁺, Rb⁺, Cs⁺, Be²⁺, Mg²⁺, Ca²⁺, Sr²⁺, Ba²⁺, andmixtures thereof.

In some embodiments, the nanoparticle composition further includes anaqueous liquid. For example, the nanoparticle composition can include atleast one of water, brine, produced water, flowback water, brackishwater, fresh water, Arab-D-brine, sea water, mineral waters, and otherwaters of varying salinity and mineral concentration. The aqueous liquidcan include at least one of a drilling fluid, a fracturing fluid, adiverting fluid, and a lost circulation treatment fluid.

In some embodiments, the method further includes obtaining or providingthe composition. The obtaining or providing of the composition can occurabove-surface. The obtaining or providing of the composition can occurin the subterranean formation.

In some embodiments, the nanoparticle is a silica nanoparticle, a rareearth upconverting nanoparticle, or a polymer nanoparticle. For example,the nanoparticle can be a polystyrene nanoparticle or a carbonaceousnanoparticle such as a carbon black nanoparticle, a carbon nanotube, agraphene nanoparticle, or graphene platelets.

In some embodiments, the nanoparticle is a metal oxide nanoparticle. Forexample, the metal oxide nanoparticle can be an iron oxide nanoparticle,a nickel oxide nanoparticle, or a cobalt oxide nanoparticle. Thenanoparticle can include a metal oxide including Zn, Cr, Co, Dy, Er, Eu,Gd, Gd, Pr, Nd, In, Pr, Sm, Tb, Tm, and combinations thereof. In someembodiments, the nanoparticle is a superparamagnetic nanoparticle. Insome embodiments, the nanoparticle includes a fluoride. For example, thenanoparticle can include upconverting rare earth nanoparticles such asdoped YF₄ nanoparticles.

In some embodiments, the coated nanoparticle has particle size of about10 nanometers (“nm”) to about 1,000 nm.

In some embodiments, the cross-linked carbohydrate-based coatingincludes a carbohydrate including a monosaccharide, an oligosaccharide,a polysaccharide, and mixtures thereof. In some embodiments, thepolysaccharide is selected from the group consisting of an alginate, achitosan, a curdlan, a dextran, a derivatized dextran, an emulsan, agalactoglucopolysaccharide, a gellan, a glucuronan, anN-acetyl-glucosamine, an N-acetyl-heparosan, a hyaluronic acid, akefiran, a lentinan, a levan, a mauran, a pullulan, a scleroglucan, aschizophyllan, a stewartan, a succinoglycan, a xanthan, a diutan, awelan, a starch, a derivatized starch, a tamarind, a tragacanth, a guargum, a derivatized guar gum (for example, a hydroxypropyl guar, acarboxy methyl guar, or a carboxymethyl hydroxypropyl guar), a gumghatti, a gum arabic, a locust bean gum, a cellulose, and a derivatizedcellulose. For example, the polysaccharide can be a dextran.

In some embodiments, the polysaccharide has an average molecular weightof about 1,000 number average molecular weight (“MW”) to about 150,000MW. For example, the polysaccharide can be dextran with a number averagemolecular weight of about 1,000 MW to about 150,000 MW.

In some embodiments, the cross-linked carbohydrate-based coating is thereaction product of a cross-linking reaction between an epoxide-basedcompound and a carbohydrate. The epoxide-based compound can be selectedfrom the group consisting of polyethylene glycol diglycidyl ether,epichlorohydrin, 1,4-butanediol diglycidyl ether, ethylene glycoldiglycidyl ether, 1,6-hexanediol diglycidyl ether, propylene glycoldiglycidyl ether, poly(propyleneglycol)diglycidyl ether),poly(tetramethylene glycol)diglycidyl ether, neopentyl glycol diglycidylether, polyglycerol polyglycidyl ether, diglycerol polyglycidyl ether,glycerol polyglycidyl ether, trimethylpropane polyglycidyl ether,1,2-(bis(2,3-epoxypropoxy)ethylene), pentaerythritol glycidyl ether,pentaerythritol polyglycidyl ether, sorbitol polyglycidyl ether, andmixtures thereof. In some embodiments, the epoxide-based compound ispentaerythritol glycidyl ether.

In some embodiments, the cross-linked carbohydrate-based coating is areaction product of quenching reaction between the cross-linkedcarbohydrate-based coating and an amine-functionalized compound. Theamine-functionalized compound can have the structure:

The variable R¹, at each occurrence, can be independently selected from—H, —OH, or a substituted or unsubstituted (C₁-C₁₀)hyrdocarbyl. Forexample, the variable R¹ can be independently selected from —H, —OH, or—(C₁-C₁₀)alkyl-OH. In some embodiments, the amine-functionalizedcompound is 2-amino-2-hydroxymethyl-propane-1,3-diol.

In some embodiments, the method further includes aggregating andprecipitating the coated nanoparticles in the subterranean formation bythe addition of a kosmotropic ion. In some embodiments, the method is amethod of fluid diversion and further includes aggregating, oraggregating and precipitating, the coated nanoparticles in thesubterranean formation by the addition of a kosmotropic ion. In someembodiments, the method is a method of conformance control and furtherincludes aggregating, or aggregating and precipitating of the coatednanoparticles in the subterranean formation by the addition of akosmotropic ion.

In some embodiments, the method further includes aggregating the coatednanoparticles at an oil-water interface. For example, the coatednanoparticles can be aggregated at one or more oil-water interfaces bythe addition of a chaotropic ion.

In some embodiments, the coated nanoparticle has a hydrodynamic diameterof about 10 nm to about 150 nm. For example, the coated nanoparticle canhave a hydrodynamic diameter of about 20 nm to about 60 nm. In someembodiments, the coated nanoparticles of the composition have ahydrodynamic diameter of less than about 100 nm after heating at 90° C.in seawater for 7 days.

The coated nanoparticles of the composition can have a hydrodynamicdiameter that is less than the hydrodynamic diameter of similar coatednanoparticles in a similar composition without the ion.

In some embodiments, the coated nanoparticles of the composition have alower critical solution temperature of greater than about 90° C.

In some embodiments, the coated nanoparticles of the composition have ahigher permeability as compared to similar coated nanoparticles in asimilar composition without the ion.

In some embodiments, the method further includes combining thecomposition with an aqueous or oil-based fluid including a drillingfluid, a stimulation fluid, a fracturing fluid, a spotting fluid, aclean-up fluid, a completion fluid, a remedial treatment fluid, anabandonment fluid, a pill, an acidizing fluid, a cementing fluid, apacker fluid, a logging fluid, or a combination thereof, to form amixture, in which the placing the composition in the subterraneanformation includes placing the mixture in the subterranean formation.

In some embodiments, at least one of prior to, during, and after theplacing of the composition in the subterranean formation, thecomposition is used in the subterranean formation, at least one of aloneand in combination with other materials, as a drilling fluid,stimulation fluid, fracturing fluid, spotting fluid, clean-up fluid,completion fluid, remedial treatment fluid, abandonment fluid, pill,acidizing fluid, cementing fluid, packer fluid, logging fluid, or acombination thereof.

In some embodiments, the composition further includes a saline, a salt,an aqueous base, an oil (e.g., a synthetic fluid oil phase), an organicsolvent, an aqueous solution, an alcohol or polyol (e.g., cellulose orstarch), an alkalinity control agent, an acidity control agent, adensity control agent, a density modifier, an emulsifier, a dispersant,a polymeric stabilizer, a crosslinking agent, a polyacrylamide, apolymer, an antioxidant, a heat stabilizer, a foam control agent, adiluent, a plasticizer, a filler or inorganic particle, a pigment, adye, a precipitating agent, a rheology modifier, a oil-wetting agent, aweight reducing additive, a heavy-weight additive, a set retardingadditive, a surfactant, a corrosion inhibitor, a gas, a lost circulationmaterial, a filtration control additive, a fiber, a thixotropicadditive, a breaker, a curing accelerator, a curing retarder, a pHmodifier, a chelating agent, a scale inhibitor, an enzyme, a resin, awater control material, an oxidizer, a marker, a Portland cement, apozzolana cement, a gypsum cement, a high alumina content cement, a slagcement, a silica cement, a fly ash, a metakaolin, a shale, a zeolite, acrystalline silica compound, an amorphous silica, fibers, a hydratableclay, a microsphere, a pozzolan lime, or a combination thereof.

In some embodiments, the composition further includes a proppant, aresin-coated proppant, or a combination thereof.

In some embodiments, the method further includes processing thecomposition exiting the annulus with at least one fluid processing unitto generate a cleaned composition and recirculating the cleanedcomposition through the wellbore.

Also provided in this disclosure, is a method of treating a subterraneanformation, the method including placing in a subterranean formation ananoparticle composition including (i) a coated nanoparticle including(a) an iron oxide nanoparticle and (b) a cross-linked carbohydrate-basedcoating including dextran, pentaerythritol glycidyl ether, and2-amino-2-hydroxymethyl-propane-1,3-diol; and (ii) an ion includingCa²⁺, in which the dextran is cross-linked by pentaerythritol glycidylether.

Also provided in this disclosure, is a system including a nanoparticlecomposition including (i) a coated nanoparticle including a nanoparticleand a cross-linked carbohydrate-based coating, and (ii) an ion selectedfrom the group consisting of Li⁺, Na⁺, K⁺, Rb^(+,) Cs⁺, Be²⁺, Mg²⁺,Ca²⁺, Sr²⁺, Ba²⁺, and mixtures thereof; and (iii) a subterraneanformation including the composition therein.

Also provided in this disclosure, is a nanoparticle composition fortreatment of a subterranean formation, the nanoparticle compositionincluding (i) a coated nanoparticle including a nanoparticle and across-linked carbohydrate-based coating, and (ii) an ion selected fromthe group consisting of Li⁺, Na⁺, K⁺, Rb^(+,) Cs⁺, Be²⁺, Mg²⁺, Ca²⁺,Sr²⁺, Ba²⁺, and mixtures thereof. The composition can further include adownhole fluid.

Also provided in this disclosure, is a composition for treatment of asubterranean formation, the composition including (i) a coatednanoparticle including an iron oxide nanoparticle and a cross-linkedcarbohydrate-based coating including dextran, pentaerythritol glycidylether, and 2-amino-2-hydroxymethyl-propane-1,3-diol in which the dextranis cross-linked by pentaerythritol glycidyl ether and (ii) an ionincluding Ca²⁺.

Various embodiments of the methods and compositions provided in thisdisclosure provide certain advantages over other methods andcompositions, at least some of which are unexpected. For example, themethods and compositions provided in this disclosure provide a strategyto stabilizing nanomaterials in high saline, high temperaturesubterranean formations.

For example, an unexpected synergism between polysaccharide coatings andcalcium ions has been discovered, which facilitates their use in oilreservoirs (for example, Saudi Arabian oil reservoirs). Further, thestandard seawater used as injection fluid in oil reservoirs (forexample, Saudi Arabian oil reservoirs) is not conducive to the use ofpolysaccharide coated nanomaterials. It has been unexpectedly discoveredthat the use of polysaccharide coated nanomaterials is possible throughaddition of ions (for example, calcium ions) to the seawater fluid. Insome embodiments, methods and compositions provided in this disclosureutilize inexpensive, readily available and environmentally friendlycomponents.

In some embodiments, the methods and compositions provided in thisdisclosure can be used to identify oil rich regions via imagingtechniques or to lower the interfacial tension between oil and water forenhanced oil recovery (“EOR”) applications.

In some embodiments, the methods and compositions provided in thisdisclosure can be used to selectively precipitate the nanomaterials insubterranean formations for fluid diversion or conformance controloperations.

DESCRIPTION OF DRAWINGS

FIG. 1 shows dynamic light scattering determination of dextran coatednanoparticle hydrodynamic diameter, as provided in this disclosure.

FIG. 2 shows a Cryo-transmission electron microscopy (TEM) image ofdextran coated superparamagnetic nanoparticles, as provided in thisdisclosure.

FIG. 3 shows an optical micrograph depicting response of an aqueoussuspension of dextran coated superparamagnetic nanoparticles exposed toan external magnetic field, as provided in this disclosure.

FIG. 4 shows the dynamic light scattering results of polysaccharidecoated nanoparticles in LS Arab-D brine (left) and seawater (right)after heating at 90° C. for the specified period of time.

FIG. 5 shows the hydrodynamic diameter (D) of polysaccharide coatednanoparticles as a function of heating at 90° C. in seawater andseawater doped with 50 mM CaCl₂, as provided in this disclosure.

FIG. 6 shows an optical micrograph depicting the impact of calcium ionremoval on the colloidal stability of polysaccharide coatednanoparticles, as provided in this disclosure.

FIG. 7 shows a concentration versus absorbance calibration curve forsuperparamagnetic nanoparticles at 388 nm, as provided in thisdisclosure

FIG. 8 shows the percent concentration of nanoparticles in the effluentstream normalized by the influent concentration for three experimentalruns, as provided in this disclosure.

FIG. 9 shows percent recovery data demonstrating the effects of fluidtype of nanoparticle recovery, as provided in this disclosure.

DETAILED DESCRIPTION

Reference will now be made in detail to certain embodiments of thedisclosed subject matter, examples of which are illustrated in part inthe accompanying drawings. While the disclosed subject matter will bedescribed in conjunction with the enumerated claims, it will beunderstood that the exemplified subject matter is not intended to limitthe claims to the disclosed subject matter.

Values expressed in a range format should be interpreted in a flexiblemanner to include not only the numerical values explicitly recited asthe limits of the range, but also to include all the individualnumerical values or sub-ranges encompassed within that range as if eachnumerical value and sub-range is explicitly recited. For example, arange of “about 0.1% to about 5%” or “about 0.1% to 5%” should beinterpreted to include not just about 0.1% to about 5%, but also theindividual values (for example, 1%, 2%, 3%, and 4%) and the sub-ranges(for example, 0.1% to 0.5%, 1.1% to 2.2%, 3.3% to 4.4%) within theindicated range. The statement “about X to Y” has the same meaning as“about X to about Y,” unless indicated otherwise. Likewise, thestatement “about X, Y, or about Z” has the same meaning as “about X,about Y, or about Z,” unless indicated otherwise.

In this document, the terms “a,” “an,” or “the” are used to include oneor more than one unless the context clearly dictates otherwise. The term“or” is used to refer to a nonexclusive “or” unless otherwise indicated.The statement “at least one of A and B” has the same meaning as “A, B,or A and B.” In addition, it is to be understood that the phraseology orterminology employed in this disclosure, and not otherwise defined, isfor the purpose of description only and not of limitation. Any use ofsection headings is intended to aid reading of the document and is notto be interpreted as limiting; information that is relevant to a sectionheading may occur within or outside of that particular section.

All publications, patents, and patent documents referred to in thisdocument are incorporated by reference in this disclosure in theirentirety, as though individually incorporated by reference. In the eventof inconsistent usages between this document and those documents soincorporated by reference, the usage in the incorporated referenceshould be considered supplementary to that of this document; forirreconcilable inconsistencies, the usage in this document controls.

In the methods of manufacturing described in this disclosure, the actscan be carried out in any order, except when a temporal or operationalsequence is explicitly recited. Furthermore, specified acts can becarried out concurrently unless explicit claim language recites thatthey be carried out separately. For example, a claimed act of doing Xand a claimed act of doing Y can be conducted simultaneously within asingle operation, and the resulting process will fall within the literalscope of the claimed process.

The term “about” as used in this disclosure can allow for a degree ofvariability in a value or range, for example, within 10%, within 5%, orwithin 1% of a stated value or of a stated limit of a range.

The term “substantially” as used in this disclosure refers to a majorityof, or mostly, as in at least about 50%, 60%, 70%, 80%, 90%, 95%, 96%,97%, 98%, 99%, 99.5%, 99.9%, 99.99%, or at least about 99.999% or more.

The term “organic group” as used in this disclosure refers to but is notlimited to any carbon-containing functional group. For example, anoxygen-containing group such as an alkoxy group, aryloxy group,aralkyloxy group, oxo(carbonyl) group, a carboxyl group including acarboxylic acid, carboxylate, and a carboxylate ester; asulfur-containing group such as an alkyl and aryl sulfide group; andother heteroatom-containing groups. Non-limiting examples of organicgroups include OR, OOR, OC(O)N(R)₂, CN, CF₃, OCF₃, R, C(O),methylenedioxy, ethylenedioxy, N(R)₂, SR, SOR, SO₂R, SO₂N(R)₂, SO₃R,C(O)R, C(O)C(O)R, C(O)CH₂C(O)R, C(S)R, C(O)OR, OC(O)R, C(O)N(R)₂,OC(O)N(R)₂, C(S)N(R)₂, (CH₂)₀₋₂N(R)C(O)R, (CH₂)₀₋₂N(R)N(R)₂,N(R)N(R)C(O)R, N(R)N(R)C(O)OR, N(R)N(R)CON(R)₂, N(R)SO₂R, N(R)SO₂N(R)₂,N(R)C(O)OR, N(R)C(O)R, N(R)C(S)R, N(R)C(O)N(R)₂, N(R)C(S)N(R)₂,N(COR)COR, N(OR)R, C(═NH)N(R)₂, C(O)N(OR)R, or C(═NOR)R, in which R canbe hydrogen (in examples that include other carbon atoms) or acarbon-based moiety, and in which the carbon-based moiety can itself befurther substituted.

The term “substituted” as used in this disclosure refers to an organicgroup as defined in this disclosure or molecule in which one or morehydrogen atoms contained therein are replaced by one or morenon-hydrogen atoms. The term “functional group” or “substituent” as usedin this disclosure refers to a group that can be or is substituted ontoa molecule or onto an organic group. Examples of substituents orfunctional groups include, but are not limited to, a halogen (forexample, F, Cl, Br, and I); an oxygen atom in groups such as hydroxygroups, alkoxy groups, aryloxy groups, aralkyloxy groups, oxo(carbonyl)groups, carboxyl groups including carboxylic acids, carboxylates, andcarboxylate esters; a sulfur atom in groups such as thiol groups, alkyland aryl sulfide groups, sulfoxide groups, sulfone groups, sulfonylgroups, and sulfonamide groups; a nitrogen atom in groups such asamines, hydroxyamines, nitriles, nitro groups, N-oxides, hydrazides,azides, and enamines; and other heteroatoms in various other groups.

The term “alkyl” as used in this disclosure refers to straight chain andbranched alkyl groups and cycloalkyl groups having from 1 to 40 carbonatoms, 1 to about 20 carbon atoms, 1 to 12 carbons or, in someembodiments, from 1 to 8 carbon atoms. Examples of straight chain alkylgroups include those with from 1 to 8 carbon atoms such as methyl,ethyl, n-propyl, n-butyl, n-pentyl, n-hexyl, n-heptyl, and n-octylgroups. Examples of branched alkyl groups include, but are not limitedto, isopropyl, iso-butyl, sec-butyl, t-butyl, neopentyl, isopentyl, and2,2-dimethylpropyl groups. As used in this disclosure, the term “alkyl”encompasses n-alkyl, isoalkyl, and anteisoalkyl groups as well as otherbranched chain forms of alkyl. Representative substituted alkyl groupscan be substituted one or more times with any of the groups listed inthis disclosure, for example, amino, hydroxy, cyano, carboxy, nitro,thio, alkoxy, and halogen groups.

The term “alkenyl” as used in this disclosure refers to straight andbranched chain and cyclic alkyl groups as defined in this disclosure,except that at least one double bond exists between two carbon atoms.Thus, alkenyl groups have from 2 to 40 carbon atoms, or 2 to about 20carbon atoms, or 2 to 12 carbons or, in some embodiments, from 2 to 8carbon atoms. Examples include, but are not limited to vinyl,—CH═CH(CH₃), —CH═C(CH₃)₂, —C(CH₃)═CH₂, —C(CH₃)═CH(CH₃), —C(CH₂CH₃)═CH₂,cyclohexenyl, cyclopentenyl, cyclohexadienyl, butadienyl, pentadienyl,and hexadienyl among others.

The term “alkynyl” as used in this disclosure refers to straight andbranched chain alkyl groups, except that at least one triple bond existsbetween two carbon atoms. Thus, alkynyl groups have from 2 to 40 carbonatoms, 2 to about 20 carbon atoms, or from 2 to 12 carbons or, in someembodiments, from 2 to 8 carbon atoms. Examples include, but are notlimited to —C≡CH, —CC(CH₃), —C≡C(CH₂CH₃), —CH₂C≡CH, —CH₂C≡C(CH₃), and—CH₂C≡C(CH₂CH₃) among others.

The term “acyl” as used in this disclosure refers to a group containinga carbonyl moiety in which the group is bonded via the carbonyl carbonatom. The carbonyl carbon atom is also bonded to another carbon atom,which can be part of an alkyl, aryl, aralkyl cycloalkyl,cycloalkylalkyl, heterocyclyl, heterocyclylalkyl, heteroaryl,heteroarylalkyl group or the like. In the special case in which thecarbonyl carbon atom is bonded to a hydrogen, the group is a “formyl”group, an acyl group as the term is defined in this disclosure. An acylgroup can include 0 to about 12-20 or 12-40 additional carbon atomsbonded to the carbonyl group. An acyl group can include double or triplebonds within the meaning in this disclosure. An acryloyl group is anexample of an acyl group. An acyl group can also include heteroatomswithin the meaning here. A nicotinoyl group (pyridyl-3-carbonyl) is anexample of an acyl group within the meaning in this disclosure. Otherexamples include acetyl, benzoyl, phenylacetyl, pyridylacetyl,cinnamoyl, and acryloyl groups and the like. When the group containingthe carbon atom that is bonded to the carbonyl carbon atom contains ahalogen, the group is termed a “haloacyl” group. An example is atrifluoroacetyl group.

The term “cycloalkyl” as used in this disclosure refers to cyclic alkylgroups such as, but not limited to, cyclopropyl, cyclobutyl,cyclopentyl, cyclohexyl, cycloheptyl, and cyclooctyl groups. In someembodiments, the cycloalkyl group can have 3 to about 8-12 ring members,whereas in other embodiments the number of ring carbon atoms range from3 to 4, 5, 6, or 7. Cycloalkyl groups further include polycycliccycloalkyl groups such as, but not limited to, norbornyl, adamantyl,bornyl, camphenyl, isocamphenyl, and carenyl groups, and fused ringssuch as, but not limited to, decalinyl, and the like. Cycloalkyl groupsalso include rings that are substituted with straight or branched chainalkyl groups as defined in this disclosure. Representative substitutedcycloalkyl groups can be mono-substituted or substituted more than once,such as, but not limited to, 2,2-, 2,3-, 2,4-2,5- or 2,6-disubstitutedcyclohexyl groups or mono-, di- or tri-substituted norbornyl orcycloheptyl groups, which can be substituted with, for example, amino,hydroxy, cyano, carboxy, nitro, thio, alkoxy, and halogen groups. Theterm “cycloalkenyl” alone or in combination denotes a cyclic alkenylgroup.

The term “aryl” as used in this disclosure refers to cyclic aromatichydrocarbons that do not contain heteroatoms in the ring. Thus arylgroups include, but are not limited to, phenyl, azulenyl, heptalenyl,biphenyl, indacenyl, fluorenyl, phenanthrenyl, triphenylenyl, pyrenyl,naphthacenyl, chrysenyl, biphenylenyl, anthracenyl, and naphthyl groups.In some embodiments, aryl groups contain about 6 to about 14 carbons inthe ring portions of the groups. Aryl groups can be unsubstituted orsubstituted, as defined in this disclosure. Representative substitutedaryl groups can be mono-substituted or substituted more than once, suchas, but not limited to, 2-, 3-, 4-, 5-, or 6-substituted phenyl or 2-8substituted naphthyl groups, which can be substituted with carbon ornon-carbon groups such as those listed in this disclosure.

The term “aralkyl” as used in this disclosure refers to alkyl groups asdefined in this disclosure in which a hydrogen or carbon bond of analkyl group is replaced with a bond to an aryl group as defined in thisdisclosure. Representative aralkyl groups include benzyl and phenylethylgroups and fused (cycloalkylaryl)alkyl groups such as 4-ethyl-indanyl.Aralkenyl groups are alkenyl groups as defined in this disclosure inwhich a hydrogen or carbon bond of an alkyl group is replaced with abond to an aryl group as defined in this disclosure.

The term “heterocyclyl” as used in this disclosure refers to aromaticand non-aromatic ring compounds containing three or more ring members,of which one or more is a heteroatom such as, but not limited to, N, O,and S. Thus, a heterocyclyl can be a cycloheteroalkyl, or a heteroaryl,or if polycyclic, any combination thereof. In some embodiments,heterocyclyl groups include 3 to about 20 ring members, whereas othersuch groups have 3 to about 15 ring members. A heterocyclyl groupdesignated as a C2-heterocyclyl can be a 5-ring with two carbon atomsand three heteroatoms, a 6-ring with two carbon atoms and fourheteroatoms and so forth. Likewise a C4-heterocyclyl can be a 5-ringwith one heteroatom, a 6-ring with two heteroatoms, and so forth. Thenumber of carbon atoms plus the number of heteroatoms equals the totalnumber of ring atoms. A heterocyclyl ring can also include one or moredouble bonds. A heteroaryl ring is an embodiment of a heterocyclylgroup. The phrase “heterocyclyl group” includes fused ring speciesincluding those that include fused aromatic and non-aromatic groups.

The term “heterocyclylalkyl” as used in this disclosure refers to alkylgroups as defined in this disclosure in which a hydrogen or carbon bondof an alkyl group as defined in this disclosure is replaced with a bondto a heterocyclyl group as defined in this disclosure. Representativeheterocyclyl alkyl groups include, but are not limited to, furan-2-ylmethyl, furan-3-yl methyl, pyridine-3-yl methyl, tetrahydrofuran-2-ylethyl, and indol-2-yl propyl.

The term “heteroarylalkyl” as used in this disclosure refers to alkylgroups as defined in this disclosure in which a hydrogen or carbon bondof an alkyl group is replaced with a bond to a heteroaryl group asdefined in this disclosure.

The term “alkoxy” as used in this disclosure refers to an oxygen atomconnected to an alkyl group, including a cycloalkyl group, as aredefined in this disclosure. Examples of linear alkoxy groups include butare not limited to methoxy, ethoxy, propoxy, butoxy, pentyloxy,hexyloxy, and the like. Examples of branched alkoxy include but are notlimited to isopropoxy, sec-butoxy, tert-butoxy, isopentyloxy,isohexyloxy, and the like. Examples of cyclic alkoxy include but are notlimited to cyclopropyloxy, cyclobutyloxy, cyclopentyloxy, cyclohexyloxy,and the like. An alkoxy group can include one to about 12-20 or about12-40 carbon atoms bonded to the oxygen atom, and can further includedouble or triple bonds, and can also include heteroatoms. For example,an allyloxy group is an alkoxy group within the meaning in thisdisclosure. A methoxyethoxy group is also an alkoxy group within themeaning in this disclosure, as is a methylenedioxy group in a contextwhere two adjacent atoms of a structure are substituted therewith.

The term “amine” as used in this disclosure refers to primary,secondary, and tertiary amines having, for example, the formulaN(group)3 in which each group can independently be H or non-H, such asalkyl, aryl, and the like. Amines include but are not limited to R—NH₂,for example, alkylamines, arylamines, alkylarylamines; R₂NH in whicheach R is independently selected, such as dialkylamines, diarylamines,aralkylamines, heterocyclylamines and the like; and R₃N in which each Ris independently selected, such as trialkylamines, dialkylarylamines,alkyldiarylamines, triarylamines, and the like. The term “amine” alsoincludes ammonium ions as used in this disclosure.

The term “amino group” as used in this disclosure refers to asubstituent of the form —NH₂, —NHR, —NR₂, —NR₃ ⁺, in which each R isindependently selected, and protonated forms of each, except for —NR₃ ⁺,which cannot be protonated. Accordingly, any compound substituted withan amino group can be viewed as an amine. An “amino group” within themeaning in this disclosure can be a primary, secondary, tertiary, orquaternary amino group. An “alkylamino” group includes a monoalkylamino,dialkylamino, and trialkylamino group.

The terms “halo,” “halogen,” or “halide” group, as used in thisdisclosure, by themselves or as part of another substituent, mean,unless otherwise stated, a fluorine, chlorine, bromine, or iodine atom.

The term “haloalkyl” group, as used in this disclosure, includesmono-halo alkyl groups, poly-halo alkyl groups in which all halo atomscan be the same or different, and per-halo alkyl groups, in which allhydrogen atoms are replaced by halogen atoms, such as fluoro. Examplesof haloalkyl include trifluoromethyl, 1,1-dichloroethyl,1,2-dichloroethyl, 1,3-dibromo-3,3-difluoropropyl, perfluorobutyl, andthe like.

The term “hydrocarbon” as used in this disclosure refers to a functionalgroup or molecule that includes carbon and hydrogen atoms. The term canalso refer to a functional group or molecule that normally includes bothcarbon and hydrogen atoms but in which all the hydrogen atoms aresubstituted with other functional groups.

As used in this disclosure, the term “hydrocarbyl” refers to afunctional group derived from a straight chain, branched, or cyclichydrocarbon, and can be alkyl, alkenyl, alkynyl, aryl, cycloalkyl, acyl,or any combination thereof.

The term “solvent” as used in this disclosure refers to a liquid thatcan dissolve a solid, another liquid, or a gas to form a solution.Non-limiting examples of solvents are silicones, organic compounds,water, alcohols, ionic liquids, and supercritical fluids.

The term “room temperature” as used in this disclosure refers to atemperature of about 15° C. to about 28° C.

The term “standard temperature and pressure” as used in this disclosurerefers to 20° C. and 101 kPa.

The term “downhole” as used in this disclosure refers to under thesurface of the earth, such as a location within or fluidly connected toa wellbore.

As used in this disclosure, the term “drilling fluid” refers to fluids,slurries, or muds used in drilling operations downhole, such as duringthe formation of the wellbore.

As used in this disclosure, the term “stimulation fluid” refers tofluids or slurries used downhole during stimulation activities of thewell that can increase the production of a well, including perforationactivities. In some examples, a stimulation fluid can include afracturing fluid or an acidizing fluid.

As used in this disclosure, the term “clean-up fluid” refers to fluidsor slurries used downhole during clean-up activities of the well, suchas any treatment to remove material obstructing the flow of desiredmaterial from the subterranean formation. In one example, a clean-upfluid can be an acidification treatment to remove material formed by oneor more perforation treatments. In another example, a clean-up fluid canbe used to remove a filter cake.

As used in this disclosure, the term “fracturing fluid” refers to fluidsor slurries used downhole during fracturing operations.

As used in this disclosure, the term “spotting fluid” refers to fluidsor slurries used downhole during spotting operations, and can be anyfluid designed for localized treatment of a downhole region. In oneexample, a spotting fluid can include a lost circulation material fortreatment of a specific section of the wellbore, such as to seal offfractures in the wellbore and prevent sag. In another example, aspotting fluid can include a water control material. In some examples, aspotting fluid can be designed to free a stuck piece of drilling orextraction equipment, can reduce torque and drag with drillinglubricants, prevent differential sticking, promote wellbore stability,and can help to control mud weight.

As used in this disclosure, the term “completion fluid” refers to fluidsor slurries used downhole during the completion phase of a well,including cementing compositions.

As used in this disclosure, the term “remedial treatment fluid” refersto fluids or slurries used downhole for remedial treatment of a well.Remedial treatments can include treatments designed to increase ormaintain the production rate of a well, such as stimulation or clean-uptreatments.

As used in this disclosure, the term “abandonment fluid” refers tofluids or slurries used downhole during or preceding the abandonmentphase of a well.

As used in this disclosure, the term “acidizing fluid” refers to fluidsor slurries used downhole during acidizing treatments. In one example,an acidizing fluid is used in a clean-up operation to remove materialobstructing the flow of desired material, such as material formed duringa perforation operation. In some examples, an acidizing fluid can beused for damage removal.

As used in this disclosure, the term “cementing fluid” refers to fluidsor slurries used during cementing operations of a well. For example, acementing fluid can include an aqueous mixture including at least one ofcement and cement kiln dust. In another example, a cementing fluid caninclude a curable resinous material such as a polymer that is in an atleast partially uncured state.

As used in this disclosure, the term “water control material” refers toa solid or liquid material that interacts with aqueous materialdownhole, such that hydrophobic material can more easily travel to thesurface and such that hydrophilic material (including water) can lesseasily travel to the surface. A water control material can be used totreat a well to cause the proportion of water produced to decrease andto cause the proportion of hydrocarbons produced to increase, such as byselectively binding together material between water-producingsubterranean formations and the wellbore while still allowinghydrocarbon-producing formations to maintain output.

As used in this disclosure, the term “packer fluid” refers to fluids orslurries that can be placed in the annular region of a well betweentubing and outer casing above a packer. In various examples, the packerfluid can provide hydrostatic pressure in order to lower differentialpressure across the sealing element, lower differential pressure on thewellbore and casing to prevent collapse, and protect metals andelastomers from corrosion.

As used in this disclosure, the term “fluid” refers to liquids and gels,unless otherwise indicated.

As used in this disclosure, the term “subterranean material” or“subterranean formation” refers to any material under the surface of theearth, including under the surface of the bottom of the ocean. Forexample, a subterranean formation or material can be any section of awellbore and any section of a subterranean petroleum- or water-producingformation or region in fluid contact with the wellbore. Placing amaterial in a subterranean formation can include contacting the materialwith any section of a wellbore or with any subterranean region in fluidcontact therewith. Subterranean materials can include any materialsplaced into the wellbore such as cement, drill shafts, liners, tubing,casing, or screens; placing a material in a subterranean formation caninclude contacting with such subterranean materials. In some examples, asubterranean formation or material can be any below-ground region thatcan produce liquid or gaseous petroleum materials, water, or any sectionbelow-ground in fluid contact therewith. For example, a subterraneanformation or material can be at least one of an area desired to befractured, a fracture or an area surrounding a fracture, and a flowpathway or an area surrounding a flow pathway, in which a fracture or aflow pathway can be optionally fluidly connected to a subterraneanpetroleum- or water-producing region, directly or through one or morefractures or flow pathways.

As used in this disclosure, “treatment of a subterranean formation” caninclude any activity directed to extraction of water or petroleummaterials from a subterranean petroleum—or water-producing formation orregion, for example, including drilling, stimulation, hydraulicfracturing, clean-up, acidizing, completion, cementing, remedialtreatment, abandonment, aquifer remediation, identifying oil richregions via imaging techniques, and the like.

As used in this disclosure, a “flow pathway” downhole can include anysuitable subterranean flow pathway through which two subterraneanlocations are in fluid connection. The flow pathway can be sufficientfor petroleum or water to flow from one subterranean location to thewellbore or vice-versa. A flow pathway can include at least one of ahydraulic fracture, and a fluid connection across a screen, acrossgravel pack, across proppant, including across resin-bonded proppant orproppant deposited in a fracture, and across sand. A flow pathway caninclude a natural subterranean passageway through which fluids can flow.In some embodiments, a flow pathway can be a water source and caninclude water. In some embodiments, a flow pathway can be a petroleumsource and can include petroleum. In some embodiments, a flow pathwaycan be sufficient to divert from a wellbore, fracture, or flow pathwayconnected thereto at least one of water, a downhole fluid, or a producedhydrocarbon.

As used in this disclosure, a “carrier fluid” refers to any suitablefluid for suspending, dissolving, mixing, or emulsifying with one ormore materials to form a composition. For example, the carrier fluid canbe at least one of crude oil, dipropylene glycol methyl ether,dipropylene glycol dimethyl ether, dipropylene glycol methyl ether,dipropylene glycol dimethyl ether, dimethyl formamide, diethylene glycolmethyl ether, ethylene glycol butyl ether, diethylene glycol butylether, butylglycidyl ether, propylene carbonate, D-limonene, a C₂-C₄₀fatty acid C₁-C₁₀ alkyl ester (for example, a fatty acid methyl ester),tetrahydrofurfuryl methacrylate, tetrahydrofurfuryl acrylate, 2-butoxyethanol, butyl acetate, butyl lactate, furfuryl acetate, dimethylsulfoxide, dimethyl formamide, a petroleum distillation product offraction (for example, diesel, kerosene, napthas, and the like) mineraloil, a hydrocarbon oil, a hydrocarbon including an aromaticcarbon-carbon bond (for example, benzene, toluene), a hydrocarbonincluding an alpha olefin, xylenes, an ionic liquid, methyl ethylketone, an ester of oxalic, maleic or succinic acid, methanol, ethanol,propanol (iso- or normal-), butyl alcohol (iso-, tert-, or normal-), analiphatic hydrocarbon (for example, cyclohexanone, hexane), water,brine, produced water, flowback water, brackish water, and sea water.The fluid can form about 0.001 weight percent (wt %) to about 99.999 wt% of a composition, or a mixture including the same, or about 0.001 wt %or less, 0.01 wt %, 0.1, 1, 2, 3, 4, 5, 6, 8, 10, 15, 20, 25, 30, 35,40, 45, 50, 55, 60, 65, 70, 75, 80, 85, 90, 95, 96, 97, 98, 99, 99.9,99.99, or about 99.999 wt % or more.

Method of Treating a Subterranean Formation

Provided in this disclosure is a method of treating subterraneanformations. The method includes placing in a subterranean formation ananoparticle composition. The nanoparticle composition includes (i) acoated nanoparticle including a nanoparticle and a cross-linkedcarbohydrate-based coating and (ii) an ion selected from the groupconsisting of Li⁺, Na⁺, K⁺, Rb⁺, Cs⁺, Be²⁺, Mg²⁺, Ca²⁺, Sr²⁺, Ba²⁺, andmixtures thereof.

In some embodiments, the nanoparticle composition further includes anaqueous liquid. For example, the nanoparticle composition can include atleast one of water, brine, produced water, flowback water, brackishwater, Arab-D-brine, and sea water. In some embodiments, the at leastone type of water can serve as the source for some or all of the ionsselected from the group consisting of Li⁺, Na⁺, K⁺, Rb⁺, Cs⁺, Be²⁺,Mg²⁺, Ca²⁺, Sr²⁺, Ba²⁺, and mixtures thereof. The aqueous liquid caninclude at least one of a drilling fluid, a fracturing fluid, adiverting fluid, an injection fluid, and a lost circulation treatmentfluid.

In some embodiments, the method further includes obtaining or providingthe composition, in which the obtaining or providing of the compositionoccurs above-surface. In some embodiments, the method further includesobtaining or providing the composition, in which the obtaining orproviding of the composition occurs in the subterranean formation.

The nanoparticle can be a metal oxide nanoparticle. For example, themetal oxide nanoparticle can be an iron oxide nanoparticle, a nickeloxide nanoparticle, or a cobalt oxide nanoparticle. The nanoparticle caninclude a metal oxide including Zn, Cr, Co, Dy, Er, Eu, Gd, Gd, Pr, Nd,In, Pr, Sm, Tb, Tm, and combinations thereof. In some embodiments, thenanoparticle is a superparamagnetic nanoparticle. As used in thisdisclosure, the term “superparamagnetic nanoparticle” refers to ananoparticle that exhibits strong paramagnetic behavior in the presenceof an applied magnetic field. In some embodiments, the superparamagneticnanoparticles can include iron oxides, such as Fe₃O₄ and γ-Fe₂O₃, puremetals, such as Fe and Co, spinel-type ferromagnets, such as MgFe₂O₄,MnFe₂O₄, and CoFe₂O₄, as well as alloys, such as CoPt₃ and FePt. Forexample, the nanoparticles can include superparamagnetic iron oxidecores. Nanoparticles including a superparamagnetic core (e.g.,superparamagnetic nanoparticles) can exhibits strong paramagneticbehavior in the presence of an applied magnetic field. In the absence ofan applied field, superparamagnetic nanoparticles can exhibit nomagnetic moment. This is due to the nanometer length scale of themagnetic domains in the superparamagnetic nanoparticle. In someembodiments, these superparamagnetic nanoparticles can be used ascontrast agents for electromagnetic crosswell imaging. The change inmagnetic susceptibility of the composition including superparamagneticnanoparticles provides contrast against native fluids. Consequently, thecompositions described in this disclosure provide for an increase inmagnetic susceptibility without a loss in colloidal stability.

In some embodiments, the nanoparticle can be a polystyrene nanoparticleor a carbonaceous nanoparticle such as a carbon black nanoparticle, acarbon nanotube, a graphene nanoparticle, graphene platelets or anyother suitable nanomaterial.

In some embodiments, the nanoparticles have a particle size of about 10nm to about 1,000 nm. For example, the nanoparticle can have a particlesize of about 10 nm to about 100 nm, about 20 nm to about 80 nm, or lessthan about 100 nm. In some embodiments, the nanoparticles in thecomposition can have an average size of about 10 nm to about 1,000 nm.For example, the nanoparticle can have an average size of about 10 nm toabout 100 nm, about 20 nm to about 80 nm, or less than about 100 nm. Asused in this disclosure, the term “average size” refers to thearithmetic mean of the distribution of nanoparticle sizes in a pluralityof nanoparticles. The nanoparticle size can be determined by dynamiclight scattering prior to forming the coated nanoparticle or by scanningelectron microscopy after the formation of the coated nanoparticle.

The cross-linked carbohydrate-based coating can include a carbohydrateincluding a monosaccharide, an oligosaccharide, a polysaccharide, andmixtures thereof. In some embodiments, the polysaccharide is selectedfrom the group consisting of an alginate, a chitosan, a curdlan, adextran, a derivatized dextran, an emulsan, agalactoglucopolysaccharide, a gellan, a glucuronan, anN-acetyl-glucosamine, an N-acetyl-heparosan, a hyaluronic acid, akefiran, a lentinan, a levan, a mauran, a pullulan, a scleroglucan, aschizophyllan, a stewartan, a succinoglycan, a xanthan, a diutan, awelan, a starch, a derivatized starch, a tamarind, a tragacanth, a guargum, a derivatized guar gum (for example, a hydroxypropyl guar, acarboxy methyl guar, or a carboxymethyl hydroxypropyl guar), a gumghatti, a gum arabic, a locust bean gum, a cellulose, and a derivatizedcellulose (for example, a carboxymethyl cellulose, a hydroxyethylcellulose, a carboxymethyl hydroxyethyl cellulose, a hydroxypropylcellulose, or a methyl hydroxy ethyl cellulose). In some embodiments,the polysaccharide can be dextran.

The polysaccharide can have a number average molecular weight of about1,000 MW to about 150,000 MW. For example, the polysaccharide can have anumber average molecular weight of about 10,000 MW to about 140,000 MW,about 30,000 MW to about 130,000 MW, 50,000 MW to about 120,000 MW,70,000 MW to about 110,000 MW, or about 80,000 MW to about 100,000 MW orabout 1,000 MW, 5,000 MW, 10,000 MW, 20,000 MW, 30,000 MW, 40,000 MW,50,000 MW, 60,000 MW, 70,000 MW, 80,000 MW, 90,000 MW, 100,000 MW,110,000 MW, 120,000 MW, 130,000 MW, 140,000 MW, or about 150,000 MW orgreater.

The polysaccharide can be dextran with a number average molecular weightof about 1,000 MW to about 150,000 MW. For example, the dextran can havea number average molecular weight of about 10,000 MW to about 140,000MW, about 30,000 MW to about 130,000 MW, 50,000 MW to about 120,000 MW,70,000 MW to about 110,000 MW, or about 80,000 MW to about 100,000 MW orabout 1,000 MW, 5,000 MW, 10,000 MW, 20,000 MW, 30,000 MW, 40,000 MW,50,000 MW, 60,000 MW, 70,000 MW, 80,000 MW, 90,000 MW, 100,000 MW,110,000 MW, 120,000 MW, 130,000 MW, 140,000 MW, or about 150,000 MW orgreater.

In some embodiments, the cross-linked carbohydrate-based coating is thereaction product of a cross-linking reaction between an epoxide-basedcompound and a carbohydrate. Cross-linking the carbohydrate-basedcoating can ensure that the carbohydrate based coating remainsassociated with the underlying nanoparticle. The epoxide-based compoundcan be selected from the group consisting of polyethylene glycoldiglycidyl ether, epichlorohydrin, 1,4-butanediol diglycidyl ether,ethylene glycol diglycidyl ether, 1,6-hexanediol diglycidyl ether,propylene glycol diglycidyl ether, poly(propylene glycol)diglycidylether), poly(tetramethylene glycol)diglycidyl ether, neopentyl glycoldiglycidyl ether, polyglycerol polyglycidyl ether, diglycerolpolyglycidyl ether, glycerol polyglycidyl ether, trimethylpropanepolyglycidyl ether, 1,2-(bis(2,3-epoxypropoxy)ethylene), pentaerythritolglycidyl ether, pentaerythritol polyglycidyl ether, sorbitolpolyglycidyl ether, and mixtures thereof In some embodiments, theepoxide-based compound is pentaerythritol glycidyl ether.

The cross-linked carbohydrate-based coating can be the reaction productof a quenching reaction between the cross-linked carbohydrate-basedcoating and an amine-functionalized compound. Quenching thecross-linked, carbohydrate based coating can involve reacting an aminewith unreacted epoxides present in the cross-linked, carbohydrate-basedcoating. Additionally, quenching the unreacted epoxides can serve toprevent undesired cross-linking between nanoparticles. Theamine-functionalized compound can have the structure:

The variable R¹, at each occurrence, can be independently selected from—H, —OH, or a substituted or unsubstituted (C₁-C₁₀)hyrdocarbyl. Forexample, the variable R¹ can be independently selected from —H, —OH, or—(C₁-C₁₀)alkyl-OH. In some embodiments, the amine-functionalizedcompound is 2-amino-2-hydroxymethyl-propane-1,3-diol.

In some embodiments, the composition further includes a counterion. Forexample, the counterion can be a halide, such as fluoride, chloride,iodide, or bromide. In other examples, the counterion can be nitrate,hydrogen sulfate, dihydrogen phosphate, bicarbonate, nitrite,perchlorate, iodate, chlorate, bromate, chlorite, hypochlorite,hypobromite, cyanide, amide, cyanate, hydroxide, permanganate. Thecounterion can be a conjugate base of any carboxylic acid, such asacetate or formate.

In some embodiments, the method further includes aggregating andprecipitating the coated nanoparticles in the subterranean formation bythe addition of an additional ion, such as a kosmotropic ion (e.g.,magnesium). In some embodiments, the method is a method of fluiddiversion and further includes aggregating, or aggregating andprecipitating, the coated nanoparticles in the subterranean formation bythe addition of a kosmotropic ion. In some embodiments, the method is amethod of conformance control and further includes aggregating, oraggregating and precipitating, of the coated nanoparticles in thesubterranean formation by the addition of a kosmotropic ion. Forexample, after the composition has been placed in the subterraneanformation a kosmotropic ion may be added to the composition. Addition ofthe kosmotropic ion can lead to aggregation, or aggregation andprecipitation, of the coated nanoparticles in the subterraneanformation. Such, compositions including kosmotropic ions are useful influid diversion or conformance control.

As used in this disclosure, the term “kosmotropic ion” refers to ionsthat contribute to the stability and structure of water-waterinteractions. Kosmotropes typically cause water molecules to favorablyinteract, which also stabilizes intermolecular interactions inmacromolecules. Examples of ionic kosmotropic ions include sulfate,phosphate, Mg²⁺, Li⁺, and any other suitable substance. Based on freeenergy of hydration (ΔG_(hydr)) of the salts, an increasing negativeΔG_(hydr), results in a more kosmotropic salt, for example. Othersuitable kosmotropes may include a sulfate, phosphate, hydrogenphosphatesalt, ammonium sulfate, sodium sulfate, citrates, oxalates, and anyother order increasing substance. The counterion may include Group IAmetal ions, Group IIA metal ions, ammonium ions, and other suitableions.

In some embodiments, the method further includes aggregating the coatednanoparticles at an oil-water interface. For example, the coatednanoparticles can be aggregated at one or more oil-water interfaces bythe addition of a chaotropic ion.

As used in this disclosure, the term “chaotripoc ion” refers to ionsthat disrupt the three dimensional structure of water. Chaotropestypically interfere with stabilizing intra-molecular interactionsmediated by non-covalent forces, such as hydrogen bonds, Van der Waalsforces, and hydrophobic effects. Examples of chaotropes include urea,guanidinium chloride, and lithium perchlorate.

The coated nanoparticles of the composition can have a hydrodynamicdiameter of about 10 nm to about 150 nm. For example, the coatednanoparticles of the composition can have a hydrodynamic diameter ofabout 20 nm to about 60 nm, 20 nm to about 80 nm, or about 20 nm toabout 120 nm. In some embodiments, the coated nanoparticles of thecomposition can have a hydrodynamic diameter of less than about 100 nmafter heating at 90° C. in seawater (e.g., synthetic seawater) for 7days. For example, the coated nanoparticles of the composition can havea hydrodynamic diameter of less than about 100 nm after heating at 90°C. in seawater for 7 days when they are at a concentration of about 100parts per million (ppm, as used herein 1 ppm is equal to 1 mg/L) toabout 2,000 ppm. In some embodiment, the coated nanoparticles of thecomposition can have a hydrodynamic diameter of less than about 90 nm,less than about 80 nm, less than about 70 nm, or less than about 60 nmafter heating at 90° C. in seawater for 7 days. For example, coatednanoparticles of the composition can have a hydrodynamic diameter ofless than about 90 nm, less than about 80 nm, less than about 70 nm, orless than about 60 nm after heating at 90° C. in seawater for 7 dayswhen they are at a concentration of about 100 parts per million (ppm) toabout 2,000 ppm.

The coated nanoparticles of the composition can have a hydrodynamicdiameter that is less than the hydrodynamic diameter of similar coatednanoparticles in a similar composition without the ion. For example, thecoated nanoparticles of the composition can have a hydrodynamic diameterthat is less than the hydrodynamic diameter of similar coatednanoparticles in a similar composition without the ion after spendingabout 7 days in seawater at a temperature of about 90° C.

In some embodiments, the coated nanoparticles of the composition have alower critical solution temperature of greater than about 90° C. Forexample, the coated nanoparticles of the composition have a lowercritical solution temperature of greater than about 90° C., about 95°C., about 100° C., or greater than about 110° C.

In some embodiments, the coated nanoparticles of the composition have ahigher permeability as compared to similar coated nanoparticles in asimilar composition without the ion. As used in this disclosure, theterm “permeability,” refers to the proportionality constant between thefluid flow rate and the applied pressure gradient. The particles of thecomposition can be more stable than particles a similar compositionwithout the ion (e.g., calcium) and, thus, less aggregation takes place,preventing permeability reduction. Typically, decreases in reservoirpermeability result from clogging of pores and reduced flow pathways.

The method can further include combining the composition with an aqueousfluid including a drilling fluid, a stimulation fluid, a fracturingfluid, a spotting fluid, a clean-up fluid, a completion fluid, aremedial treatment fluid, an abandonment fluid, a pill, an acidizingfluid, a cementing fluid, a packer fluid, a logging fluid, or acombination thereof, to form a mixture, in which the placing thecomposition in the subterranean formation includes placing the mixturein the subterranean formation. The term aqueous fluid can include W/O(water-in-oil) emulsions and W/O/W (water-in-oil-in-water) emulsions.

In some embodiments, at least one of prior to, during, and after theplacing of the composition in the subterranean formation, thecomposition is used in the subterranean formation, at least one of aloneand in combination with other materials, as a drilling fluid, astimulation fluid, a fracturing fluid, a spotting fluid, a clean-upfluid, a completion fluid, a remedial treatment fluid, an abandonmentfluid, a pill, an acidizing fluid, a cementing fluid, a packer fluid, alogging fluid, or a combination thereof.

The composition can further include a saline, a salt, an aqueous base,an oil (e.g., a synthetic fluid oil phase), an organic solvent, anaqueous solution, an alcohol or polyol (e.g., cellulose or starch), analkalinity control agent, an acidity control agent, a density controlagent, a density modifier, an emulsifier, a dispersant, a polymericstabilizer, a crosslinking agent, a polyacrylamide, a polymer, anantioxidant, a heat stabilizer, a foam control agent, a diluent, aplasticizer, a filler or inorganic particle, a pigment, a dye, aprecipitating agent, a rheology modifier, a oil-wetting agent, a weightreducing additive, a heavy-weight additive, a set retarding additive, asurfactant, a corrosion inhibitor, a gas, a lost circulation material, afiltration control additive, a fiber, a thixotropic additive, a breaker,a curing accelerator, a curing retarder, a pH modifier, a chelatingagent, a scale inhibitor, an enzyme, a resin, a water control material,an oxidizer, a marker, a Portland cement, a pozzolana cement, a gypsumcement, a high alumina content cement, a slag cement, a silica cement, afly ash, a metakaolin, shale, a zeolite, a crystalline silica compound,an amorphous silica, fibers, a hydratable clay, a microsphere, apozzolan lime, or a combination thereof.

In some embodiments, the composition further includes a proppant, aresin-coated proppant, or a combination thereof.

The method can further includes processing the composition exiting theannulus with at least one fluid processing unit to generate a cleanedcomposition and recirculating the cleaned composition through thewellbore.

Also provided in this disclosure is a method of treating a subterraneanformation, the method including placing in a subterranean formation ananoparticle composition including (i) a coated nanoparticle including(a) an iron oxide nanoparticle and (b) a cross-linked carbohydrate-basedcoating including dextran, pentaerythritol glycidyl ether, and2-amino-2-hydroxymethyl-propane-1,3-diol; and (ii) an ion includingCa²⁺, in which the dextran is cross-linked by pentaerythritol glycidylether.

Composition

Also provided in this disclosure, is a nanoparticle composition fortreatment of a subterranean formation, the nanoparticle compositionincluding (i) a coated nanoparticle including a nanoparticle and across-linked carbohydrate-based coating, and (ii) an ion selected fromthe group consisting of Li⁺, Na⁺, K⁺, Rb^(+,) Cs⁺, Be²⁺, Mg²⁺, Ca²⁺,Sr²⁺, Ba²⁺, and mixtures thereof. The composition can further include adownhole fluid.

Also provided in this disclosure, is a composition for treatment of asubterranean formation, the composition including (i) a coatednanoparticle including an iron oxide nanoparticle and a cross-linkedcarbohydrate-based coating including dextran, pentaerythritol glycidylether, and 2-amino-2-hydroxymethyl-propane-1,3-diol in which the dextranis cross-linked by pentaerythritol glycidyl ether and (ii) an ionincluding Ca^(2+.)

Other Components

The composition including the (i) coated nanoparticle including thenanoparticle and the cross-linked carbohydrate-based coating and (ii)the ion selected from the group consisting of Li⁺, Na⁺, K⁺, Rb⁺ Cs⁺,Be²⁺, Mg²⁺, Ca²⁺, Sr²⁺, Ba²⁺, and mixtures thereof, can further includeone or more suitable components. The additional components can be anycomponents, such that the composition can be used as described in thisdisclosure.

In some embodiments, the composition includes one or more viscosifiers.The viscosifier can be any suitable viscosifier. The viscosifier canaffect the viscosity of the composition or a solvent that contacts thecomposition at any suitable time and location. In some embodiments, theviscosifier provides an increased viscosity at least one of beforeinjection into the subterranean formation, at the time of injection intothe subterranean formation, during travel through a tubular disposed ina borehole, once the composition reaches a particular subterraneanlocation, or some period of time after the composition reaches aparticular subterranean location. In some embodiments, the viscosifiercan be about 0.0001 wt % to about 10 wt % of the composition.

The viscosifier can include at least one of a linear polysaccharide, andpoly((C₂-C₁₀)alkenylene), in which at each occurrence, the(C₂-C₁₀)alkenylene is independently substituted or unsubstituted. Insome embodiments, the viscosifier can include at least one ofpoly(acrylic acid) or (C1-C5)alkyl esters thereof, poly(methacrylicacid) or (C₁-C₅)alkyl esters thereof, poly(vinyl acetate), poly(vinylalcohol), poly(ethylene glycol), poly(vinyl pyrrolidone),polyacrylamide, poly (hydroxyethyl methacrylate), alginate, chitosan,curdlan, dextran, emulsan, gellan, glucuronan, N-acetyl-glucosamine,N-acetyl-heparosan, hyaluronic acid, kefiran, lentinan, levan, mauran,pullulan, scleroglucan, schizophyllan, stewartan, succinoglycan,xanthan, welan, derivatized starch, tamarind, tragacanth, guar gum,derivatized guar (for example, hydroxypropyl guar, carboxy methyl guar,or carboxymethyl hydroxylpropyl guar), gum ghatti, gum arabic, locustbean gum, and derivatized cellulose (for example, carboxymethylcellulose, hydroxyethyl cellulose, carboxymethyl hydroxyethyl cellulose,hydroxypropyl cellulose, or methyl hydroxyl ethyl cellulose).

The viscosifier can include a poly(vinyl alcohol) homopolymer,poly(vinyl alcohol) copolymer, a crosslinked poly(vinyl alcohol)homopolymer, and a crosslinked poly(vinyl alcohol) copolymer. Theviscosifier can include a poly(vinyl alcohol) copolymer or a crosslinkedpoly(vinyl alcohol) copolymer including at least one of a graft, linear,branched, block, and random copolymer of vinyl alcohol and at least oneof a substituted or unsubstituted (C₂-C₅₀)hydrocarbyl having at leastone aliphatic unsaturated C—C bond therein, and a substituted orunsubstituted (C₂-C₅₀)alkene. The viscosifier can include a poly(vinylalcohol) copolymer or a crosslinked poly(vinyl alcohol) copolymerincluding at least one of a graft, linear, branched, block, and randomcopolymer of vinyl alcohol and at least one of vinyl phosphonic acid,vinylidene diphosphonic acid, substituted or unsubstituted2-acrylamido-2-methylpropanesulfonic acid, a substituted orunsubstituted (C₁-C₂₀)alkenoic acid, propenoic acid, butenoic acid,pentenoic acid, hexenoic acid, octenoic acid, nonenoic acid, decenoicacid, acrylic acid, methacrylic acid, hydroxypropyl acrylic acid,acrylamide, fumaric acid, methacrylic acid, hydroxypropyl acrylic acid,vinyl phosphonic acid, vinylidene diphosphonic acid, itaconic acid,crotonic acid, mesoconic acid, citraconic acid, styrene sulfonic acid,allyl sulfonic acid, methallyl sulfonic acid, vinyl sulfonic acid, and asubstituted or unsubstituted (C₁-C₂₀)alkyl ester thereof. Theviscosifier can include a poly(vinyl alcohol) copolymer or a crosslinkedpoly(vinyl alcohol) copolymer including at least one of a graft, linear,branched, block, and random copolymer of vinyl alcohol and at least oneof vinyl acetate, vinyl propanoate, vinyl butanoate, vinyl pentanoate,vinyl hexanoate, vinyl 2-methyl butanoate, vinyl 3-ethylpentanoate, andvinyl 3-ethylhexanoate, maleic anhydride, a substituted or unsubstituted(C₁-C₂₀)alkenoic substituted or unsubstituted (C₁-C₂₀)alkanoicanhydride, a substituted or unsubstituted (C₁-C₂₀)alkenoic substitutedor unsubstituted (C₁-C₂₀)alkenoic anhydride, propenoic acid anhydride,butenoic acid anhydride, pentenoic acid anhydride, hexenoic acidanhydride, octenoic acid anhydride, nonenoic acid anhydride, decenoicacid anhydride, acrylic acid anhydride, fumaric acid anhydride,methacrylic acid anhydride, hydroxypropyl acrylic acid anhydride, vinylphosphonic acid anhydride, vinylidene diphosphonic acid anhydride,itaconic acid anhydride, crotonic acid anhydride, mesoconic acidanhydride, citraconic acid anhydride, styrene sulfonic acid anhydride,allyl sulfonic acid anhydride, methallyl sulfonic acid anhydride, vinylsulfonic acid anhydride, and an N—(C1-C₁₀)alkenyl nitrogen containingsubstituted or unsubstituted (C₁-C₁₀)heterocycle. The viscosifier caninclude a poly(vinyl alcohol) copolymer or a crosslinked poly(vinylalcohol) copolymer including at least one of a graft, linear, branched,block, and random copolymer that includes apoly(vinylalcohol)-poly(acrylamide) copolymer, apoly(vinylalcohol)-poly(2-acrylamido-2-methylpropanesulfonic acid)copolymer, or a poly(vinylalcohol)-poly(N-vinylpyrrolidone) copolymer.The viscosifier can include a crosslinked poly(vinyl alcohol)homopolymer or copolymer including a crosslinker including at least oneof an aldehyde, an aldehyde-forming compound, a carboxylic acid or anester thereof, a sulfonic acid or an ester thereof, a phosphonic acid oran ester thereof, an acid anhydride, and an epihalohydrin.

The composition can further include a crosslinker. The crosslinker canbe any suitable crosslinker. The crosslinker can be present in anysuitable concentration, such as more, less, or an equal concentration ascompared to the concentration of the crosslinker. The crosslinker caninclude at least one of boric acid, borax, a borate, a(C1-C30)hydrocarbylboronic acid, a (C1-C30)hydrocarbyl ester of a(C1-C30)hydrocarbylboronic acid, a (C1-C30)hydrocarbylboronicacid-modified polyacrylamide, ferric chloride, disodium octaboratetetrahydrate, sodium metaborate, sodium diborate, sodium tetraborate,disodium tetraborate, a pentaborate, ulexite, colemanite, magnesiumoxide, zirconium lactate, zirconium triethanol amine, zirconium lactatetriethanolamine, zirconium carbonate, zirconium acetylacetonate,zirconium malate, zirconium citrate, zirconium diisopropylamine lactate,zirconium glycolate, zirconium triethanol amine glycolate, zirconiumlactate glycolate, titanium lactate, titanium malate, titanium citrate,titanium ammonium lactate, titanium triethanolamine, titaniumacetylacetonate, aluminum lactate, and aluminum citrate. The compositioncan include any suitable proportion of the crosslinker, such as about0.1 wt % to about 50 wt %, or about 0.1 wt % to about 20 wt %, or about0.001 wt %, 0.01, 0.1, 1, 2, 3, 4, 5, 10, 15, 20, 30, 40, 50, 60, 70,80, 85, 90, 91, 92, 93, 94, 95, 96, 97, 98, or about 99 wt % or more ofthe composition.

In some embodiments, the composition, or a mixture including the same,can include any suitable amount of any suitable material used in adownhole fluid. For example, the composition or a mixture including thesame can include water, saline, aqueous base, acid, oil, organicsolvent, synthetic fluid oil phase, aqueous solution, alcohol or polyol,cellulose, starch, alkalinity control agents, acidity control agents,density control agents, density modifiers, emulsifiers, dispersants,polymeric stabilizers, crosslinking agents, polyacrylamide, a polymer orcombination of polymers, antioxidants, heat stabilizers, foam controlagents, solvents, diluents, plasticizer, filler or inorganic particle,pigment, dye, precipitating agent, rheology modifier, oil-wettingagents, set retarding additives, surfactants, gases, weight reducingadditives, heavy-weight additives, lost circulation materials,filtration control additives, fibers, thixotropic additives, breakers,crosslinkers, rheology modifiers, curing accelerators, curing retarders,pH modifiers, chelating agents, scale inhibitors, enzymes, resins, watercontrol materials, oxidizers, markers, Portland cement, pozzolanacement, gypsum cement, high alumina content cement, slag cement, silicacement, fly ash, metakaolin, shale, zeolite, a crystalline silicacompound, amorphous silica, hydratable clays, microspheres, lime, or acombination thereof.

A drilling fluid, also known as a drilling mud or simply “mud,” is aspecially designed fluid that is circulated through a wellbore as thewellbore is being drilled to facilitate the drilling operation. Thedrilling fluid can be water-based or oil-based. The drilling fluid cancarry cuttings up from beneath and around the bit, transport them up theannulus, and allow their separation. Also, a drilling fluid can cool andlubricate the drill head as well as reduce friction between the drillstring and the sides of the hole. The drilling fluid aids in support ofthe drill pipe and drill head, and provides a hydrostatic head tomaintain the integrity of the wellbore walls and prevent well blowouts.Specific drilling fluid systems can be selected to optimize a drillingoperation in accordance with the characteristics of a particulargeological formation. The drilling fluid can be formulated to preventunwanted influxes of formation fluids from permeable rocks and also toform a thin, low permeability filter cake that temporarily seals pores,other openings, and formations penetrated by the bit. In water-baseddrilling fluids, solid particles are suspended in a water or brinesolution containing other components. Oils or other non-aqueous liquidscan be emulsified in the water or brine or at least partiallysolubilized (for less hydrophobic non-aqueous liquids), but water is thecontinuous phase. A drilling fluid can be present in the mixture withthe composition including the crosslinkable ampholyte polymer and thecrosslinker, or a crosslinked reaction product thereof, in any suitableamount, such as about 1 wt % or less, about 2 wt %, 3, 4, 5, 10, 15, 20,30, 40, 50, 60, 70, 80, 85, 90, 95, 96, 97, 98, 99, 99.9, 99.99, 99.999,or about 99.999.9 wt % or more of the mixture.

A water-based drilling fluid in methods provided in this disclosure canbe any suitable water-based drilling fluid. In some embodiments, thedrilling fluid can include at least one of water (fresh or brine), asalt (for example, calcium chloride, sodium chloride, potassiumchloride, magnesium chloride, calcium bromide, sodium bromide, potassiumbromide, calcium nitrate, sodium formate, potassium formate, cesiumformate), aqueous base (for example, sodium hydroxide or potassiumhydroxide), alcohol or polyol, cellulose, starches, alkalinity controlagents, density control agents such as a density modifier (for example,barium sulfate), surfactants (for example, betaines, alkali metalalkylene acetates, sultaines, ether carboxylates), emulsifiers,dispersants, polymeric stabilizers, crosslinking agents,polyacrylamides, polymers or combinations of polymers, antioxidants,heat stabilizers, foam control agents, foaming agents, solvents,diluents, plasticizers, filler or inorganic particles (for example,silica), pigments, dyes, precipitating agents (for example, silicates oraluminum complexes), and rheology modifiers such as thickeners orviscosifiers (for example, xanthan gum). Any ingredient listed in thisparagraph can be either present or not present in the mixture.

An oil-based drilling fluid or mud in methods provided in thisdisclosure can be any suitable oil-based drilling fluid. In someembodiments the drilling fluid can include at least one of an oil-basedfluid (or synthetic fluid), saline, aqueous solution, emulsifiers, otheragents of additives for suspension control, weight or density control,oil-wetting agents, fluid loss or filtration control agents, andrheology control agents. For example, see H. C. H. Darley and George R.Gray, Composition and Properties of Drilling and Completion Fluids66-67, 561-562 (5th ed. 1988). An oil-based or invert emulsion-baseddrilling fluid can include between about 10:90 to about 95:5, or about50:50 to about 95:5, by volume of oil phase to water phase. Asubstantially all oil mud includes about 100% liquid phase oil by volume(for example, substantially no internal aqueous phase).

A pill is a relatively small quantity (for example, less than about 500bbl, or less than about 200 bbl) of drilling fluid used to accomplish aspecific task that the regular drilling fluid cannot perform. Forexample, a pill can be a high-viscosity pill to, for example, help liftcuttings out of a vertical wellbore. In another example, a pill can be afreshwater pill to, for example, dissolve a salt formation. Anotherexample is a pipe-freeing pill to, for example, destroy filter cake andrelieve differential sticking forces. In another example, a pill is alost circulation material pill to, for example, plug a thief zone. Apill can include any component described in this disclosure as acomponent of a drilling fluid.

A cement fluid can include an aqueous mixture of at least one of cementand cement kiln dust. The composition including the crosslinkableampholyte polymer and the crosslinker, or a crosslinked reaction productthereof, can form a useful combination with cement or cement kiln dust.The cement kiln dust can be any suitable cement kiln dust. Cement kilndust can be formed during the manufacture of cement and can be partiallycalcined kiln feed that is removed from the gas stream and collected ina dust collector during a manufacturing process. Cement kiln dust can beadvantageously utilized in a cost-effective manner since kiln dust isoften regarded as a low value waste product of the cement industry. Someembodiments of the cement fluid can include cement kiln dust but nocement, cement kiln dust and cement, or cement but no cement kiln dust.The cement can be any suitable cement. The cement can be a hydrauliccement. A variety of cements can be utilized in accordance withembodiments of the methods described in this disclosure; for example,those including calcium, aluminum, silicon, oxygen, iron, or sulfur,which can set and harden by reaction with water. Suitable cements caninclude Portland cements, pozzolana cements, gypsum cements, highalumina content cements, slag cements, silica cements, and combinationsthereof. In some embodiments, the Portland cements that are suitable foruse in embodiments of the methods described in this disclosure areclassified as Classes A, C, H, and G cements according to the AmericanPetroleum Institute, API Specification for Materials and Testing forWell Cements, API Specification 10, Fifth Ed., Jul. 1, 1990. A cementcan be generally included in the cementing fluid in an amount sufficientto provide the desired compressive strength, density, or cost. In someembodiments, the hydraulic cement can be present in the cementing fluidin an amount in the range of from 0 wt % to about 100 wt %, 0-95 wt %,20-95 wt %, or about 50-90 wt %. A cement kiln dust can be present in anamount of at least about 0.01 wt %, or about 5 wt %-80 wt %, or about 10wt % to about 50 wt %.

Optionally, other additives can be added to a cement or kilndust-containing composition of embodiments of the methods described inthis disclosure as deemed appropriate by one skilled in the art, withthe benefit of this disclosure. Any optional ingredient listed in thisparagraph can be either present or not present in the composition. Forexample, the composition can include fly ash, metakaolin, shale,zeolite, set retarding additive, surfactant, a gas, accelerators, weightreducing additives, heavy-weight additives, lost circulation materials,filtration control additives, dispersants, and combinations thereof. Insome examples, additives can include crystalline silica compounds,amorphous silica, salts, fibers, hydratable clays, microspheres,pozzolan lime, thixotropic additives, combinations thereof, and thelike.

The composition or mixture can further include a proppant, aresin-coated proppant, an encapsulated resin, or a combination thereof.A proppant is a material that keeps an induced hydraulic fracture atleast partially open during or after a fracturing treatment. Proppantscan be transported into the subterranean formation and to the fractureusing fluid, such as fracturing fluid or another fluid. Ahigher-viscosity fluid can more effectively transport proppants to adesired location in a fracture, especially larger proppants, by moreeffectively keeping proppants in a suspended state within the fluid.Examples of proppants can include sand, gravel, glass beads, polymerbeads, ground products from shells and seeds such as walnut hulls, andmanmade materials such as ceramic proppant, bauxite, tetrafluoroethylenematerials (for example, TEFLON™ available from DuPont), fruit pitmaterials, processed wood, composite particulates prepared from a binderand fine grade particulates such as silica, alumina, fumed silica,carbon black, graphite, mica, titanium dioxide, meta-silicate, calciumsilicate, kaolin, talc, zirconia, boron, fly ash, hollow glassmicrospheres, and solid glass, or mixtures thereof. In some embodiments,proppant can have an average particle size, in which particle size isthe largest dimension of a particle, of about 0.001 mm to about 3 mm,about 0.15 mm to about 2.5 mm, about 0.25 mm to about 0.43 mm, about0.43 mm to about 0.85 mm, about 0.85 mm to about 1.18 mm, about 1.18 mmto about 1.70 mm, or about 1.70 to about 2.36 mm. In some embodiments,the proppant can have a distribution of particle sizes clustering aroundmultiple averages, such as one, two, three, or four different averageparticle sizes. The composition or mixture can include any suitableamount of proppant, such as about 0.0001 wt % to about 99.9 wt %, about0.1 wt % to about 80 wt %, or about 10 wt % to about 60 wt %, or about0.00000001 wt % or less, or about 0.000001 wt %, 0.0001, 0.001, 0.01,0.1, 1, 2, 3, 4, 5, 10, 15, 20, 30, 40, 50, 60, 70, 80, 85, 90, 91, 92,93, 94, 95, 96, 97, 98, 99, 99.9 wt %, or about 99.99 wt % or more.

System or Apparatus

Also provided in this disclosure, is a system including a nanoparticlecomposition including (i) a coated nanoparticle including a nanoparticleand a cross-linked carbohydrate-based coating, and (ii) an ion selectedfrom the group consisting of Li⁺, Na⁺, K⁺, Rb^(+,) Cs⁺, Be²⁺, Mg²⁺,Ca²⁺, Sr²⁺, Ba²⁺, and mixtures thereof and (iii) a subterraneanformation including the composition therein.

In some embodiments, the composition in the system can also include adownhole fluid, or the system can include a mixture of the compositionand downhole fluid. In some embodiments, the system can include atubular, and a pump configured to pump the composition into thesubterranean formation through the tubular.

Various embodiments provide systems and apparatus configured fordelivering the composition described in this disclosure to asubterranean location and for using the composition therein, such as fordrilling or hydraulic fracturing. In some embodiments, the system caninclude a pump fluidly coupled to a tubular (for example, any suitabletype of oilfield pipe, such as pipeline, drill pipe, production tubing,and the like), the tubular containing a composition including the coatednanoparticle and the ion, described in this disclosure.

In some embodiments, the system can include a drillstring disposed in awellbore, the drillstring including a drill bit at a downhole end of thedrillstring. The system can include an annulus between the drillstringand the wellbore. The system can also include a pump configured tocirculate the composition through the drill string, through the drillbit, and back above-surface through the annulus. The system can includea fluid processing unit configured to process the composition exitingthe annulus to generate a cleaned drilling fluid for recirculationthrough the wellbore.

EXAMPLES Example 1.1 Syntheses and Characterization

Polysaccharide-coated iron oxide nanoparticles were synthesized usingthe cold-gelation approach. In this approach, 1.35 g (grams) (0.005moles) of FeCl₃.6H₂O was dissolved in 50 mL (milliliters) of deionizedwater. To this solution was added 3.0 g of 90,000 MW dextran (branchedpolysaccharide). After addition, the reaction was cooled to 5° C.through the use of an ice water bath and subsequently deoxygenatedthrough the use of an N₂ purge. This deoxygenation/cooling cycle wasapplied for 30 minutes while vigorously stirring the reaction vesselwith a magnetic stir bar. After 30 minutes, 0.54 g (0.0027 moles) ofFeCl₂.4H₂O dissolved in 5 mL of deionized water was added to the vessel.The mixture was allowed to stir under an N₂ atmosphere for an additional10 minutes. Next, 3 mL of concentrated aqueous NH₃ solution was addeddropwise to the solution over a period of 15 minutes. During theaddition, the reaction color changed from orange to dark brown/black.After completion of addition, the reaction was heated to 80° C. for 45minutes. After heating, the reaction was allowed to cool to roomtemperature. The resulting particles were coated non-covalently with adextran sheath. Crosslinking can ensure the coating remains intactduring subterranean operations. In order to facilitate crosslinking, 2mL of pentaerythritol glycidyl ether was added to 200 mL of 1M (molar)NaOH (aq.) and 400 mg of NaBH₄ in a round bottom flask. The crudenanoparticle solution was transferred to an addition funnel, which wassubsequently mounted to the round bottom flask containing thecrosslinking formulation. The nanoparticle solution (55 mL) was addeddropwise over a period of approximately 1 hour to the vigorouslystirring crosslinking solution. The reaction was allowed to proceed atroom temperature for 24 hours. Upon completion of the 24 hour reactionperiod, 20 mL of 2M 2-amino-2-hydroxymethyl-propane-1,3-diol was addedto the crude mixture to quench any unreacted crosslinker present in themedium. This reaction was allowed to proceed for 12 hours. Uponcompletion, the reaction was purified via tangential flow filtration(100,000 MWCO filter) to provide a purified nanoparticle solution. Thedynamic light scattering results for the as synthesized materials alongwith TEM images are shown in FIG. 1 and FIG. 2. FIG. 2 shows a Cryo-TEMimage of the synthesized dextran coated superparamagnetic nanoparticles.FIG. 3 shows an optical micrograph depicting response of an aqueoussuspension of the synthesized dextran coated superparamagneticnanoparticles exposed to an external magnetic field.

Example 1.2 Formulation Fluids Containing Polysaccharide CoatedNanoparticles

Nanoparticle formulations can be injected into subterranean formationsusing seawater. The composition of seawater used in Saudi Aramco oilfield operations (along with the composition of reservoir brine) isdisplayed in Table 1.

TABLE 1 Salt Seawater LS Arab-D (g/L) NaCl 41.042 74.59 CaCl₂•2 H₂O2.385 49.79 MgCl₂•6 H₂O 17.645 13.17 BaCl₂ 0.00 0.01 Na₂SO₄ 6.343 0.6NaHCO₃ 0.165 0.51 TDS about 60,000 ppm about 120,000 ppm

Seawater possesses a lower overall total dissolved salt (TDS) contentcompared to the formation water that exists in the subterraneanenvironment. Further, salinity tends to decrease the colloidal stabilityof nanoparticles leading to flocculation and sedimentation. This processis described by Derjaguin, Landau, Verwey and Overbeek (DLVO) theory,which predicts that an increase in salinity will effectively screen anysurface charges present in the double layer of a nanoparticle andsignificantly decrease any nanoparticle-nanoparticle repulsive forcesthat would otherwise keep the particles suspended in solution. Inaddition, high salinity fluids exhibit higher surface tensions comparedto deionized water. This increase in surface tension destabilizes thenanoparticles by increasing the free energy of hydration. Based on thisunderstanding, it was unexpectedly found that the nanoparticlesdescribed in Part I are significantly more stable in reservoir brine (LSArab-D brine) compared to the lower salinity seawater. Thiscounterintuitive observation is exemplified in FIG. 4, which showsdynamic light scattering results of polysaccharide coated nanoparticlesin LS Arab-D brine (left) and seawater (right) after heating at 90° C.for the specified period of time. The increase in hydrodynamic diameterin seawater is indicative of particle aggregation.

A saturated seawater sample was prepared with CaCl₂ (50 mM) and 500 ppmof the nanoparticles described previously in Example 1.1. A controlexperiment was also setup using standard seawater. Both experiments wereheated at 90° C. for 7 days and monitored visually for flocculation aswell as via dynamic light scattering (DLS). The results of thisexperiment are displayed in FIG. 5. FIG. 5 shows the hydrodynamicdiameter (D) of polysaccharide coated nanoparticles as a function ofheating at 90° C. in seawater and seawater doped with 50 mM CaCl₂.

The results demonstrate the mitigating effects of calcium on theobserved nanoparticle instabilities in seawater. To further test this,calcium was removed from the reservoir brine (LS Arab D) and left allother components unchanged. To this solution was added 500 ppm ofnanoparticles and the experiment was heated to 90° C. A control samplewas prepared using standard reservoir brine (LS Arab D) containingcalcium ions. The results are depicted in FIG. 6. FIG. 6 shows opticalmicrograph depicting the impact of calcium ion removal on the colloidalstability of polysaccharide coated nanoparticles. 500 ppm ofpolysaccharide coated nanoparticles were injected into standardreservoir brine (left) and reservoir brine without calcium ions (right),both systems were heated to 90° C. for 7 days. A red laser pointer wasused to exemplify the increase in scattering intensity due to particleaggregation in the absence of calcium ions. Through the removal ofcalcium, the nanoparticles are rendered unstable and begin to aggregateas indicated by the increased scattering of the red laser and theincrease in hydrodynamic diameter as measured by dynamic lightscattering. These results clearly indicate the synergistic interactionbetween calcium ions and polysaccharide coated nanomaterials. By dopingseawater injection fluids with low concentrations (50 mM) of calciumsalts, formulations of stable nanomaterial suspensions for use insubterranean applications were created.

Example 1.3 Nanoparticle Transport Through Porous Media

Porous media. For columns packed with crushed rock, 70 millidarcy (mD)Indiana Limestone cores were purchased from Korcurek Industries(carbonate similar to Arab-D rock), crushed, and then sieved to producepowders of known grain sizes. Grain sizes of >250 micrometer (um),150-250 um, 106-150 um, and 45-106 um are the available options from thesieving process. Prior to column packing the porous rock fines are mixedwith the planned testing fluid (low salinity brine (B), seawater (SW),or deionized water (DI)) and placed in a vacuum chamber at −10 pound persquare inch (psi) overnight to degas and subsequent rinsing steps areused to remove any muddy residue. For all data shown here the grain sizeof 150-250 um was used.

Column, tubing, and electronics. Stainless steel tubing (OD=¼″, 55 mmlong) and reducing fittings (¼″ to 1/16″) were purchased from Swagelok.Teflon tubing (0.040″ ID, Scientific Commodities, Inc.) was used toconnect the flow from the syringe pump (Harvard Apparatus, Inc.) to thecolumn and to the pressure gauge (50 psi wet/dry differential, OmegaEngineering, Inc.). At the effluent side of the column a course filterset is inserted prior to column packing to retain the porous media butallow nanoparticle passage. The course filter consists of a 5 mm VitonO-ring (McMaster-Carr), 5 mm 0.75″ 316 Stainless steel mesh(McMaster-Carr), 5 mm Cyclopore Track Etched Membrane (Whatman, Inc),another 5 mm 0.75″ 316 Stainless Steel Mesh, and a final 5 mm VitonO-ring.

Column packing. A wet/dry column packing method was chosen to ensureconsistent and tight column packing with the wet degassed crushed rock.Briefly, a vacuum hose is connected to the outlet of the column with thefilter set in place between the bottom of the ¼″ stainless steel tubingand the ¼″ to 1/16″ reducing fitting. Then, the selected porous mediawas slowly added to the column while alternating with the fluid phase.The column was gently tapped and then pressed using a plunger to ensureeven and tight packing. This process was repeated several times untilthe column was full and suction from the vacuum no longer pulled thefluid quickly through the column.

Experimental procedure. The ¼″ to 1/16″ reducing fitting was thenattached the top for the column. The column was first rinsed with ˜30 mLof the test fluid (deionized water or brine) to ensure a saturatedcolumn and to measure the pressure drop across the column (andpermeability). Next a continuous injection of nanoparticles at 1250 ppmwas pumped into the column at a known flow rate and fractions (˜1-3 porevolumes (PV) each) were collected at the effluent starting when thenanoparticles reached the top of the packed column. For eachexperimental run, 3 mL (˜10 PV) of the particle solution was injected.Finally, the nanoparticle solution was replaced by a flush fluid(deionized water or brine) containing no nanoparticles and fractionswere collected until >20 PV appeared transparent and contained nonanoparticles.

Characterization. Nanoparticle concentration in the collected volumefractions was determined using UV-VIS absorbance (Shimadzu) based on theBeer-Lambert Law (Eq. 1).

A=α1C  (1)

Where, A is the absorbance, α is the absorbtivity (mL/(mg*mm)), 1 is thepath length (mm) and C is the concentration (mg/mL). For thesuperparamagnetic nanoparticles the absorbance was tested 388 nm. Priorto measuring the absorbance of the collected fractions, a calibrationcurve was produced to measure α (see FIG. 7 for superparamagneticnanoparticles).

In some cases the concentration of particles in the collected fractionwas very high and led to the absorbance to be outside of the linearrange measured for the calibration curve. For these fractions a dilutionwas performed such that the absorbance was within the necessary rangeand then the reported concentration and mass of nanoparticles was scaledto account for the dilution. For each cuvette the absorbance wasmeasured and then converted to concentration in mg/mL and then to massby multiplying by the volume of the collected fraction.

Finally, the permeability of the packed channel to the saturation fluidwas measured using Darcy's law:

$\kappa:=\frac{v \cdot \mu \cdot h}{\Delta \; P}$

Where κ is the permeability, μ is the viscosity, h is the column height,v is the flow rate in units distance/time (ft/day), and ΔP is thepressure drop.

After each run the column was placed in the oven to dry overnight andthe packing material was recovered and weighed to get the porosity ofthe pack. The porosity was then used to calculate the pore volume.

Results. Three miniaturized coreflood tests for each flushing fluid wereperformed with the cross-linked dextran stabilized superparamagneticnanoparticles at 1.25 mg/mL. The experimental parameters for all datasets are given in Table 2. The permeability reported is the permeabilityto each flushing fluid based on the measured pressure drop and flow rateby Eqn. 2. The permeability of the crushed rock columns was close to thecore permeability reported by the vendor showing that the columns arewell packed and closely resemble the structure of the whole cores. Lowervalues of permeability can be attributed to excess fines being releasedduring crushing and filling the large pore space.

TABLE 2 Fluid % Recovery Perm (mD) Porosity (%) DI 86.4 58 28 DI 85.8 4824 DI 82.8 45 24 SW 92.0 47 25 SW 85.2 49 21 SW 88.2 42 23 B 95.3 70 23B 95.3 49 24 B 89.4 47 25

FIG. 8 shows the percent concentration of nanoparticles in the effluentstream normalized by the influent concentration for all threeexperimental runs. In each case the concentration of nanoparticles inthe effluent stream reached that of the influent stream after more than5 pore volumes of nanoparticles entered the packed column. This dataalong with the volume of the collected fractions is used to calculatethe percentage of the total mass recovered in each fraction. The totalmass is then calculated as the total of all fractions (FIG. 9 and Table2).

These results show that the nanoparticles traverse the pore network ofboth a glass bead and crushed rock porous media and that they are stablein flowing low-salinity Arab-D brine, artificial seawater and deionizedwater at room temperature.

OTHER EMBODIMENTS

It is to be understood that while the invention has been described inconjunction with the detailed description thereof, the foregoingdescription is intended to illustrate and not limit the scope of theinvention, which is defined by the scope of the appended claims. Otheraspects, advantages, and modifications are within the scope of thefollowing claims.

What is claimed is:
 1. A method of treating a subterranean formation,the method comprising: placing in a subterranean formation ananoparticle composition comprising: a coated nanoparticle comprising aniron oxide nanoparticle and a cross-linked carbohydrate-based coatingcomprising dextran, pentaerythritol glycidyl ether, and2-amino-2-hydroxymethyl-propane-1,3-diol; and an ion comprising Ca²⁺,wherein the dextran is cross-linked by pentaerythritol glycidyl ether.